Apparatus, systems, and methods for fracturing a geological formation

ABSTRACT

The present disclosure relates, according to some embodiments, to apparatus, systems, and methods of fracturing a geological structure including the application of kinetic energy (e.g., from high velocity frack fluid) to a subterranean structure. In some embodiments, the present disclosure relates to apparatus, systems, and methods for delivery of high velocity fluid to a well using a down hole valve and/or throttling system. The present disclosure relates to apparatus, systems, and methods of generating pressure using accumulators (e.g., high pressure accumulators) at the surface of a well.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. patent application Ser. No.15/175,816, filed Jun. 7, 2016, which application is a divisional ofU.S. patent application Ser. No. 14/696,357 filed Apr. 24, 2015, whichapplication claims benefit of provisional U.S. patent application Ser.No. 61/983,836, filed Apr. 24, 2014, all of the contents of which arehereby incorporated in their entirety by reference.

FIELD OF THE DISCLOSURE

The present disclosure relates, in some embodiments, to apparatus,system, and methods of fracturing a geological structure.

BACKGROUND OF THE DISCLOSURE

Wells for the production of natural gas and other products may include awell bore to a depth of 8,000 to 12,000 feet below the surface and maybe generally vertical with optional horizontal zones. Well productionmay be initiated or reinitiated by introducing cracks or fractures inthe subterranean formation. Even though natural resources may remain ina formation, production can cease when efforts to introduce furtherfractures in the subterranean formations are unsuccessful.

SUMMARY

Accordingly, a need has arisen for improved apparatus, systems, andmethods for inducing failure (e.g., fracturing) a subterraneanformation. The present disclosure relates, according to someembodiments, to apparatus, system, and methods of fracturing ageological structure including the application of kinetic energy (e.g.,from high velocity frack fluid) to a subterranean structure. Forexample, a method of kinetically fracking a subterranean structure maycomprise (a) providing a fracking string inside a perforated wellboreliner having an interior cavity, the fracking string having an interiorchannel and spaced-apart apertures connecting the interior stringchannel and the liner cavity, (b) accelerating a fracking fluid in theinterior channel in a downhole direction to a velocity of from about 50to about 100 feet per second, and/or (c) abruptly decelerating frackingfluid flow. In some embodiments, a method may further comprise repeatingsteps (b) and (c) (e.g., in sequence). Abruptly decelerating frackingfluid flow may further comprise closing the string apertures, sealingthe interior liner cavity or combinations thereof, according to someembodiments. Accelerating a fracking fluid in the interior channel in adownhole direction may further comprise, in some embodiments, injectingthe fracking fluid at a pressure of about 8,000 psi to about 15,000 psiinto the interior channel. A pressure of 15,000 psi is required for anoverburdened pressure zone. In some embodiments, accelerating a frackingfluid in the interior channel in a downhole direction may furthercomprise (a) providing the fracking fluid at a pressure of about 8,000psi to about 15,000 psi, wherein the fracking fluid is substantiallyfree of proppant, (b) adding at least one proppant to the frackingfluid, and/or (c) injecting the fracking fluid with proppant into theinterior channel. In some embodiments, accelerating a fracking fluid inan interior channel in a downhole direction may further compriseinjecting a gas into the interior channel at a pressure of about 8,000psi to about 10,000 psi. An injected gas may be or may comprise carbondioxide, nitrogen, methane, or combinations thereof. In someembodiments, a fracking fluid may comprise up to about 30% (V/V) gas andat least about 70% (V/V) fluid (e.g., liquid). Abruptly decelerating thefracking fluid flow may further comprise delivering to the subterraneanstructure a kinetic energy pulse of finite duration of more than about12,000,000 foot-pounds, according to some embodiments. Abruptlydecelerating fracking fluid flow may further comprise, in someembodiments, delivering to the subterranean structure a kinetic energypulse of finite duration (e.g., ≤˜2 seconds, ≤˜1 seconds, ≤˜0.5 seconds,≤˜0.1 seconds) of about 2,000,000 ft lbs to about 11,000,000 ft lbs (at˜4000 gpm and ˜8000 psi) in a well about ˜12,000 foot deep.

The present disclosure also relates, in some embodiments, to systems forkinetically fracking a subterranean structure. A system for kineticallyfracking a subterranean structure may comprise, for example, (a) a wellin fluid communication with the subterranean structure, (b) a well linerinside the well, (c) a fracking string inside the well liner, thefracking string comprising a central channel, (d) a high pressure gasaccumulator in fluid communication with the central channel of thefracking string and configured to accelerate a fracking fluid downhole,(e) a high pressure gas fluid accumulator in fluid communication withthe central channel of the fracking string and configured to acceleratethe fracking fluid downhole, (f) a high pressure gas pump operablylinked to the with the high pressure gas accumulator and the highpressure gas fluid accumulator, and/or (g) a fluid velocity activatedannular valve configured to abruptly decelerate the fracking fluid. Insome embodiments, a system may further comprise from one to about twentyadditional high pressure gas pumps and/or fluid accumulator backed upfluid pumps, each independently configured to deliver, for example,about 1500 to about 2000 horsepower.

According to some embodiments, the present disclosure relates to adownhole fluid velocity-activated annular valve. A velocity-activatedannular valve may be configured for operation in a wellbore with aninserted production liner, in some embodiments. A velocity-activatedannular valve may comprise, for example, (a) an annular body having alongitudinal axis, an interior surface configured to slide along andseal a fracking string, and an exterior surface comprising a taper, thetaper extending circumferentially around the exterior surface andextending along at least a portion of the length of the body, (b) anannular packing element contacting and surrounding the taper andconfigured to translate radially outwardly upon axial movement of theramp, and/or (c) at least one aperture configured to align with acorresponding hole in the fracking string and support fluidcommunication between the inner channel of the fracking string and theliner cavity. In some embodiments, an annular valve may further comprisean annular housing surrounding an annular spring, the spring configuredfor compression and decompression with axial movement of the valve. Amaximum extent of a taper may be positioned at the more downhole end ofan annular valve and/or a minimum extent of a taper may be positioned atthe end of a valve nearer to the well head, in some embodiments. Anannular valve may further comprise, according to some embodiments, anO-ring on the inner surface configured to sealably contact the frackingstring.

According to some embodiments, the present disclosure relates to systemsfor directing fluid in a subterranean structure. A system may comprise,for example, (a) a well in fluid communication with the subterraneanstructure, (b) a well liner inside the well, (c) a fracking stringinside the well liner, the fracking string comprising a central channelfor carrying the fluid, (d) a configurable slider sleeve for directingflow of the fluid, (e) a first orifice located near the slider sleeve, apressure drop across the first orifice being determined by the flow ofthe fluid, and (f) an expandable first spring for moving the slidersleeve when the pressure drop across the first orifice falls to or belowa threshold level, the movement of the slider sleeve enabling the fluidto enter an annular space between the fracking string and the wellliner. In some embodiments, a system may further comprise a secondspring, the second spring being compressed upon the movement of theslider sleeve enabling the fluid to enter the annular space between thefracking string and the well liner. In some embodiments, a system mayfurther comprise a first snap ring for compressing or expanding thefirst spring, and a second snap ring for compressing or expanding thesecond spring. The first snap ring or the second snap ring is engagablewith the slider sleeve. In some embodiments, a valve mandrel associatedwith a system as described herein is not movable, and a valve associatedwith the system is movable. In some embodiments, both the valve mandreland the valve associated with the system are movable.

BRIEF DESCRIPTION OF THE DRAWINGS

Some embodiments of the disclosure may be understood by referring, inpart, to the present disclosure and the accompanying drawings, wherein:

FIG. 1 illustrates a fracking system according to a specific exampleembodiment of the disclosure;

FIG. 2A illustrates a section view of a fracking system having a fluidvelocity activated annulus valve in an open position according to aspecific example embodiment of the disclosure;

FIG. 2B illustrates a section view of a fracking system having a fluidvelocity activated annulus valve in a closed position according to aspecific example embodiment of the disclosure,

FIG. 2C illustrates a perspective view of the annular velocity valveshown in FIGS. 2A and 2B;

FIG. 3A illustrates a fracking system in a first position according to aspecific example embodiment of the disclosure;

FIG. 3B illustrates an enlarged view of a portion of the fracking systemillustrated in FIG. 3A;

FIG. 3C illustrates a fracking system in a second position according toa specific example embodiment of the disclosure; and

FIG. 4 illustrates a fracking system according to a specific exampleembodiment of the disclosure.

Table 1 below includes the reference numerals used in this application.The thousands and hundreds digits correspond to the figure in which theitem appears while the tens and ones digits correspond to the particularitem indicated. Similar structures share matching tens and ones digits.

TABLE 1 FIGS. FIG. FIG. 3A, 3B, FIG. 1 2 and 3C 4 System 100 300 400System 201 Programed Gas Throttling Valve 102 High Pressure GasAccumulator 104 High Pressure Gas Compressor 106 High Pressure GasSupply Line 108 High Pressure Gas Input Valve 110 High Pressure GasInlet Valve 112 Gas Side High Pressure Gas 114 Accumulator Piston 116Fluid Side 118 Programmed Throttling Valve 120 High Pressure Frack Pump122 Fluid Accumulator Make Up Line 124 Pump Bypass Line Back To Suction126 Program Controlled Fluid Bypass 128 Valve Dopant Dispenser 130Program Controlled Metering Valve 132 Frack Fluid Containing Proppants134 Gas 136 Production Liner 138 Annulus Program Controlled Valve 140Well Head 142 Production String 144 Fluid Velocity Activated Annulus 146Valve Pressure Activated Packer 148 Interior Channel 251 InteriorChannel Wall 253 Aperture 255 Threaded Flange 257 Annular Valve 259 Ramp261 Threaded Zone 263 Aperture 265 O-Ring 267 Housing 269 Threaded Ramp271 Annular Piston 273 Annular Piston Chamber 274 Packing Element 275Ramp 277 Retainer Plate 279 Threaded Ramp 281 Spring 283 Spring Chamber284 Rubber Ring 285 Restricted Flow Area 287 Production Liner 289Aperture 291 Cement 196 Geological Structure or Well Bore 297 ProductionZone 198 Induced Fracture 299 Flow port 355 Seals 358 Flow port 365Orifice 371 Spring 372 Sliding valve 373 Annulus 374 Spring 375 Orifice376 Locking taper 377 Metal expandable coil spring 378 Metal expandablecoil spring 379 Polymer element 381 Polymer element 382 Annular velocityvalve 383 Flow port 385 Snap ring 386 Snap ring 387 Production Liner 389Aperture 391 Well bore 397 Orifice 411 Spring 412 Sliding sleeve 413Snap ring 415 Spring 416 Orifice 417 Snap ring 418 Annulus 419 Seal 421Seal 422 Orifice 423

DETAILED DESCRIPTION

The present disclosure relates, according to some embodiments, toapparatus, systems, and methods of fracturing a geological structureincluding the application of kinetic energy (e.g., from high velocityfrack fluid) to a subterranean structure. In some embodiments, thepresent disclosure relates to apparatus, systems, and methods fordelivery of high velocity fluid to a well using a down hole valve and/orthrottling system. The present disclosure relates to apparatus, systems,and methods of generating pressure using accumulators (e.g., highpressure accumulators) at the surface of a well.

In some embodiments, fracturing a formation may include application of akinetic energy pulse to a formation. Repeated application of such pulsesmay have an effect that may be likened to the effect of a jackhammer.This effect coupled with the capacity to deliver energy pulses may(e.g., very high energy pulses) lead to formation of fractures instructures that are otherwise resistant to fracturing. Some embodimentsof the present disclosure may be useful for reviving wells previouslyclosed and/or initiating production from formations previously deemedunavailable with existing technology.

The present disclosure relates, in some embodiments, to methods,apparatuses, and systems for accessing and/or producing natural gasand/or other products from a subterranean source location. For example,a well bore may be provided and/or formed, the well bore having anydesired depth. For example, a well bore may be from about 500 feet toabout 35,000 feet. Shallower well bores (e.g., 500′-5,000′) may beuseful for production of water. Deeper well bores (e.g., 5,000′-35,000′)may be useful for natural gas production.

Some wells (e.g., wells in North Dakota) have may be 10,000 feet deepand have horizontal laterals with as many as 38 stages. Without limitingany embodiment of the disclosure to any particular mechanism of action,fracking sand under the force gravity may settle, for example, in one ormore lower sections of one or more laterals. If this occurs, subsequentflow may be hindered due to a parasitic pressure drop resulting fromfriction between the drilling fluid settled frack sand. Settling may goundetected, for example, where a drilling rig, upon completion ofdrilling, is replaced with a small work over or coil tubing rig forfracturing. Thereafter, when fracturing is complete, a small coil orwork over rig is brought in to clean out the well. These cleaning unitsmay have (e.g., often have) a small pump capacity and may not be capableof producing the flow velocity and volume for turbulent flow capable ofremoving sand still in lower sections of the frack string or frackingstring. When the string is removed, any sand in a horizontal sectionwould be expected to be deposited at the end of the adjacent verticalsection of the well. The presence of sand in these vertical sections maynot be detected unless the well is later worked over. The presentdisclosure relates, in some embodiments, to methods, apparatuses, andsystems that may reduce or prevent such sedimentation and/or clearsettled fracking solids, if any, from down hole locations.

Preparation

After drilling a well, a subterranean formation may be prepared forproduction by fracturing the formation using one or more apparatus,systems, and methods disclosed herein. Preparation may includeinstalling a production liner and fixing (e.g., cementing) the liner inplace. A wellbore and a production casing may be perforated in thedesired production stage (e.g., prior to fracturing). For example, apredetermined number of shots or shape charges may be loaded into aperforating gun that is then lowered or pumped into the hole to thedesired location. The charges are fired and communication with theformation is established in that stage. Preparation may includeinstalling a sliding sleeve production liner that is not cemented intoplace. A sliding sleeve liner may be selectively opened allowing longsections of open hole to be exposed to high fracturing pressures.Swellable permanent packers on the liner sleeve outer diameter isolatethe fracture zone and allow the fracture fluid and proppant to seek thepath of least resistance in areas of natural fractures or permeablesandy shale deposition. In addition to a production liner, a workingstring may be installed in the wellbore inside of the liner. In someembodiments, a 2 ⅞″ working string may be inserted in a 5½″ casing or a4½″ working string may be inserted in a 7″ casing. A work string may beinserted through the length of a lateral section if production is from ahorizontal zone. According to some embodiments, available swell packersor sliding sleeve assemblies may be used to isolate each fracture stage.

Fracking

The present disclosure relates, in some embodiments, to apparatus,systems, and methods for fracturing geological formations in whichavailable energy (e.g., energy identified in the general energy equationbelow) is applied to a formation. Energy may be applied to a formation,for example, with embodiments of disclosed apparatus and/or systems.

General energy applied to formation hydraulic fracturing may beexpressed as follows:

PE _(IN) +KE _(IN) +FW _(IN) +U _(IN) +Q ₁ =PE _(OUT) +KE _(OUT) +FW_(OUT) +U _(OUT) +Q _(OUT) +W   (I), (I).

where,

PE=potential energy,

KE=kinetic energy,

FW=flow work,

U=internal energy,

Q=heat energy,

W<0 is work done on the fluid,

W >0 is work done by the fluid,

IN (subscript)=input, and

OUT (subscript)=output.

Flow work (FW) may be expressed as the product of fluid pressuremultiplied by flow volume. Flow work (FW) may be expressed as theproduct of pressure multiplied by area multiplied by flow velocity.

Energy components in the general energy equation that store energy inthe fracture fluid product are Potential Energy (PE), Flow Work Energycomponents in the general energy equation that store energy in thefracture fluid product are Potential Energy, Flow Work, Kinetic Energy,and Internal Energy. The internal energy term “U” is the energyavailable due to the molecular activity in the product and is primarilykinetic energy within the molecule. Gas when highly compressed storespressure that can be available as an energy source in the formationfracture procedure and the use of this energy component as previouslydescribed is a major claim of this invention. (FW), Kinetic Energy (KE),and Internal Energy (U). Internal energy is a measure of the energyavailable due to the molecular activity in the product and is primarilykinetic energy within the molecule. Highly compressed gas may storepressure that may be available as an energy source in the formationfracture procedure. Internal Energy (U) may not be available in frackingprocesses that use incompressible fluids.

After dropping out the terms not applicable in the non-flow pressurebuild up in the pre-fracturing phase, the general energy equation maytake the form of: Q=U+W or in differential form: dQ=dU+dW. The energycomponent Q is heat energy either added to or subtracted from the fluid.Q may have limited relevance to some embodiments of the disclosure. Forexample, Q may be limited to embodiments in which friction heat isdissipated.

Without limiting any particular embodiment to any particular mechanismof action, a primary consideration concerning rock failure is the stressapplied through a pressure force, for example, without consideration offormation brittleness, ductility, and deposition. Generally, rockfailure may be achieved when the pressure is great enough to exceed therock's failure strength. According to some embodiments, kinetic energyavailable to act on an (isolated) hydrocarbon-bearing formation may beexpressed as follows:

$\begin{matrix}{{{KE}_{t} = {\frac{FFM}{2g}*({FV})^{2}}},} & ({II})\end{matrix}$

where,

KE_(t)=total kinetic energy,

FFM=total mass of the fracture fluid inside the working string,

g=gravity constant, and

FV=fluid velocity.

In some embodiments, potential energy (PE) may be the hydrostaticpressure at the true vertical depth (TVD) expressed as follows:

Pressure (psi)=TVD(ft)*FFD(lbs/ft³)*1 ft/144 in²   (III),

where,

FFD=frack fluid density.

A flow work component prior to formation breakdown (e.g., static flowconditions) may be stored in the internal energy component (U). Afterformation breakdown (e.g., dynamic conditions), the flow work componentmay be expressed as follows:

FW=(P _(S) +P _(HH) −P _(F))*FA*FV   (IV),

where,

P_(S)=surface pressure,

P_(HH)=hydrostatic head,

P_(F)=formation pressure,

FA=flow area, and

FV=flow velocity.

Pressure and Volume are finite values in non-flow processes. Forexample, the PV term is not shown in the differential equation,dQ=dU+dW, because the potential energy of a fluid at rest does notinclude any potential energy from pressure, which is what the PV termrepresents—the potential energy of a fluid at rest is equal to itsinternal energy (U). These conditions may exist, for example, during ahigh pressure build up phase, before formation breakdown and after thevelocity valve has closed. A compressed gas component during this phasemay have a kinetic energy component (e.g., a very large energycomponent) stored as internal energy available for use in the flow workenergy phase after formation breakdown.

According to some embodiments, an internal work string frack fluidcolumn may be allowed to accelerate (e.g., to maximum velocity due to anapplied surface pressure force from the surface accumulators). Flow backto the surface may be terminated at maximum velocity by a down the holeevent controlled annulus valve positioned on the upstream side of anactive fracture stage and on the outside diameter of the work string. Insome embodiments, a valve may be activated at a pre-determined frackfluid flow velocity. A valve may seal off flow between the work stringand the production casing.

In some embodiments, kinetic energy in accelerated (or moving) frackfluid may be converted to a pressure generally in accordance withNewton's law (e.g., unit force=mass times deceleration). Surfacepressure to accelerate a fluid column may be instantly or substantiallyinstantly available to be superimposed on a kinetic energy pressurepulse and, thereby, increase (e.g., significantly increase) formationfracture pressure.

According to some embodiments, a frack fluid may be accelerated in aworking string to any desired velocity up to any applicable physicallimits. For example, a fracking fluid may be accelerated to a velocityof up to 150 feet per second (fps), from about 10 to about 60 fps, fromabout 25 to about 75 fps, from about 40 to about 90 fps, from about 50to about 100 fps, from about 75 to about 120 fps, and/or from about 100to about 150 fps. As velocity increases, heat (e.g., friction) mayincrease. Heat may impact fracking fluid viscosity and, accordingly, maybe welcomed, controlled, or avoided, as desired or required.

As a simple illustration, according to the preceding formulae, if afracture fluid with a density of 11 lbs/gallon is accelerated to 66 feetper second in a working string having an inside diameter of 4 inches toa true vertical depth is 8,000 FT and then abruptly (e.g., substantiallyinstantaneously) decelerated, the kinetic energy pulse delivered (e.g.,to the formation) would be 3,883,424 ft lbs during a finite time period.An isolated and exposed formation (e.g., exposed after production casingperforation or by opening an available sliding casing valve) would besubjected to this energy and, according to Newton's law, thedeceleration will result in a unit pressure force acting for a shorttime period and can be expressed as F(psi)=mass times deceleration. Ifnormal formation pressure at 8000 feet is 3578 psi, there would be apressure gradient across the exposed and isolated well bore facestarting at a high value (conversion of kinetic energy to unit pressure)and decreasing to formation pressure at some distance back from the wellbore surface. If the pressure differential across the rock face isgreater than the fracture strength of the formation, fractures willoccur and the frack fluid flow state changes from static to dynamic. Insome embodiments, gas and frack fluid accumulators on the surface,having been pressured up to 8000 to 10000 psi, may supply the energy toaccelerate the fluid mass inside of the work string. Gas and fluidaccumulators may be configured to deliver constant pressure variablevolume flow so when formation fracture occurs and the frack fluid statechanges form static to dynamic the computer controlled throttling valvessupply the increased volume of fluid required to fill the fracture, butmaintain the pressure at a preset value.

Rapid deceleration of a large high velocity fluid mass may result in alarge pressure force that is the product of the mass times the velocitysquared. The resulting force may create a pressure exceeding (e.g.,greatly exceeding) the pressure required to initiate fracturepropagation in that fracture stage. The kinetic energy component in thegeneral energy equation would now be available. This component is notavailable in conventional fracturing techniques and is the only energycomponent that is nonlinear as it varies as the velocity to the squaredpower.

Existing hydraulic fracking may be performed as a constant volume,variable pressure, non-flow process as the working fracture fluid can beconsidered as incompressible. The pressure quickly builds up and, atsome pressure, the yield strength of the rock matrix and or bond betweenbedding planes is exceeded and the process then changes to a more orless steady-flow process. The only energy component in the generalenergy equation being utilized at this time in conventional fracking isthe FLOW WORK, or pressure times flow volume. The work componentgenerated by the flow work must produce a force sufficient to fracturethe rock matrix and move a mass of proppant into the fractures therebyfulfilling the work definition of force times distance and equating FlowWork=Work output.

In some embodiments, it may be desired and/or required for formationfracture pressure to be greater than the gravity force of the overburdenfor hydraulic fracturing to occur. For example, using a specific gravityof 2.5 for overburden rock and 8000 feet True Vertical Depth, thepressure required to equalize the overburden force would be 8666 PSIassuming pore pressure and TVD hydrostatic head are equal.

According to some embodiments, a fracking fluid may be formulated toinclude any desired proportion of a gas (e.g., an inert gas, CO₂, N₂,CH₄). For example, a fracking fluid may comprise up to about 5% (V/V),up to about 10% (V/V), up to about 15% (V/V), up to about 20% (V/V), upto about 25% (V/V), up to about 30% (V/V), up to about 35% (V/V), and/orup to about 40% (V/V) gas. In some embodiments, the percentage of gasmay be selected to tune balance peak pulse pressure and pulse duration.For example, a fluid column containing 30% (V/V) CO₂ and 70% (V/V) frackfluid may require additional time to decelerate due to gas compression.In some embodiments, dampening of peak pulse pressure due to higherconcentrations of gas may be desired to secure a longer pulse durationduring the static flow state.

According to some embodiments, gas injection may form a separate part ofa fluid column. For example, a gas may not be inverted nor cut with ahigher specific gravity fluid. Gas may be injected in slugs and/ormetered in at the same time as the frack fluid by throttling inletvalves. In some embodiments, using orifices to establish pressurecontrols and create a sustained harmonic motion machine optionally maybe omitted (e.g., where the pressure drop across an orifice is limitedby the orifice diameter, fluid mass, and flow rate). A relatively largevolume gas slug flowing into a fractured formation because of lessresistance to flow as compared to water, could see a pressure dropacross the orifices that would allow spring 283 to open the velocityvalve and initiate the kinetic energy cycle again.

Accumulators and Pumps

Hydraulic fracturing of hydrocarbon bearing geological formations maybenefit from and/or require the use of multiple high pressure, highvolume pumps that are connected in parallel to a common discharge line.This line leads to the wellbore and eventually the wellbore enters theproduction zone. Pumps used in this way may produce about 1500 to about2000 horsepower and, when operated in parallel, may produce a total of30000 HP available (e.g., 15 pumps×2000 HP each). Additional pumps maybe on location as replacements if any active pumps fail. Becauseabrasive frack fluid components pass through at extremely highpressures, maintenance costs may extremely high and breakdowns may befrequent. In some embodiments, however, proppant may be delivered to awell downstream of a pressure accumulator. Such delivery may alleviatewear and tear associated with the presence of proppant in earlier stagesof frack fluid production pressurization.

In some embodiments, using kinetic energy may comprise accelerating amass of fracture produce inside a fracture fluid working string to adesired velocity (e.g., a maximum velocity within the limits of thefriction pressure loss) and decelerating this mass by rapidly (andoptionally, reversibly) closing a downhole annular valve. A downholeannular valve may encircle a working string and be positioned adjacentto and upstream of a hole connecting the working string interior channelwith the liner channel. Rapid deceleration of a frack product may createa large pressure pulse or surge that (e.g., an extremely large pressurepulse or surge) is the product of a flow work energy component superimposed on the kinetic energy component immediately followed by thecontinued flow work energy component. This pulse may be applied toexposed production formation. The flow work energy component may beproduced by a system as shown in FIG. 1.

In some embodiments, surface accumulators may discharge fracture fluidfrom a bank of pre-charged accumulators at about 8000 to about 10000psi. Accumulators may be charged with any desired gas including, forexample, CH₄, N₂, CO₂, any inert gas, or combinations thereof. A fluidaccumulator may contain a floating piston that separates the gas sidefrom the frack fluid side and discharge to a common work string flowline. Discharge from a bank of accumulator's that have been pre-chargedwith CO₂, CH₄, or some other desirable injection gas at an initialpressure of 8000 to 10000 psi may also discharge to a flow line throughmetering valves. A flow line may be inserted to the beginning of thefracture stage.

The desired percentage mixture of fluid and gas, as computer controlledby high pressure metering valves, may enter a high pressure dischargeline. Fluid delivery from this system may be volume demand driven at apre-determined constant pressure. A torque convertor electric motordriven conventional frack pump will have a delayed response, forexample, about 6.66 seconds round trip in a 16000 foot well, to anincrease in down the hole volume requirement as fracturing develops dueto the time delay of the pressure decrease as a function of the velocityup the fluid stream to the pump discharge and back down to theformation.

High pressure bulk containers may inject the calculated flow rate ofproppant into a flow stream and upstream from a fracture fluid pipestring connection. This procedure eliminates abrasive proppants passingthrough an accumulator, make up frack pumps, and computer controlledvalves in the system prior to the bulk storage valves. Circulation isdown through the work string and out the end near the beginning of thefracture stage; then back up the annulus between the last insertedcasing string and the work string and out the well head annulus valve tothe mixing tank or waste pit. At maximum velocity and afterevent-controlled closure of an annular valve just upstream from theactive fracture stage, and flow may be stopped from the annulus killline valve at the surface well head.

Additional gas and fracture fluid accumulators may come on line toinstantly supplement the kinetic energy pressure surge and deliveradditional flow work component from the general equation where theprocess operates in a constant-flow mode as formation fracturing occurs.The volume of gas now in the working string and annulus acts as anenergy storage medium and the pressure content and volume content of theinternal energy (U) are available to add to the Flow Work component atformation breakdown thereby increasing the work output applied toformation fracturing and proppant wedging into the fractures. Accordingto some embodiments, a predominant component of this kinetic energyevent is the pressure surge and when almost instantly followed by aconstant pressure variable volume Flow Work energy component produced bythe surface accumulators, this compound energy application to theproducing formation may improve (e.g., significantly improve) fracturepropagation and/or increase (e.g., significantly increase) production.

Brittleness, absence of ductility, and/or deposition conditions (sandcontent etc.) may influence and/or determine the failure stress value,but failure will occur at some upper level. The greater the pressuredifferential across the perforations and rock face during the initialfracture, the greater the extent of the fracturing, according to someembodiments. Energy applied from the kinetic energy surge and almostinstant follow up from the accumulators may greatly extend the initialfractures. The unit pressure force necessary to hold open the fracturesafter failure and allow proppants to be displaced into the fracture voidis less than that necessary to exceed the formation yield strengthbecause the formation has failed.

In some embodiments, the percentage of gas volume in the fracture fluidmay be equivalent to that volume of water that is eliminated. The verylarge volume of fresh water that is now required in conventionalfracturing is causing alarm due to environmental concerns for wastewater disposal and high water usage. For example, a series of fourteenhorizontal wells drilled by QEP in the Bakken required 1,116,536 bbl. ofwater and 45,409,000 pounds of proppant. The water required would havefilled a 15 acre lake 10 feet deep. The use of 50% CO₂ or NG (naturalgas) in these wells would have eliminated 50% of the required water. Insome embodiments, less water may be required using apparatus, systems,and methods in accordance with this disclosure. A reduction in theamount of water needed may be attributable to increased efficiency offracking even if gas is not a component of the mixture.

Hydraulic Horsepower is the product of pressure and volume and both ofthese components form a linear relationship to the HP equation. Forexample if 10,000 HHP are available and it is determined that a surfacepressure of 8000 psi is desired for formation breakdown and formationpressure is the same as the hydrostatic fracture fluid column pressure,then these may offset each other and the 8000psi may be available tofracture the formation. Volume output with 10000 HP available and adischarge pressure of 8000 psi would be 2142.5 gpm. The pressurecomponent applies the unit force necessary to cause a stress in theformation matrix that is greater than the ultimate failure strength andis responsible for the fracture propagation. In some embodiments, thismay be important (e.g., the most important) constituent initiatingformation fracture. The volume component fills the fracture volume withfracture fluid and proppant and then acts as a structural member to keepthe fracture open. Fracture propagation may continue as long as thepressure exceeds the rock fracture strength but as the fracturesincrease in length and quantity, the friction pressure loss and volumerequirements are increased thereby requiring a greater pressure andvolume. Normal formation pressure at a TVD of 8000′ is 3577 psi using8.4 pound per gallon salt water. Normal fracture fluid weight is 10 to12 pounds per gallon. Using 12 lbs/gallon fluid would give an 8000′bottom of the hole pressure of 4986 psi. The formation pressure tobottom hole pressure differential would be −1409 psi. If a pressure of8000 psi is required to cause formation breakdown then the surfacepressure would need to be over 6600 psi.

According to some embodiments, a well head may be connected withautomatic computer-controlled valves to accumulators for injectingmetered volumes of CO₂, natural gas, or other gasses and fracture fluid.A manifold may be included to connect frack pumps. High pressurecontainers for proppant and/or weighting materials injection may beincluded in an apparatus and/or may be installed between anaccumulator/pump output manifold and a well head. Injection of fracturefluid and gas in a predetermined ratio may provide a fluid columncompressibility and the internal energy component may become verysignificant.

In some embodiments, a system may comprise a high-pressure gasaccumulator for pressurizing fluid (e.g., drilling fluid) to bedelivered to a down hole site. A gas accumulator may comprise, forexample, one or more cylinders (e.g., 30-inch diameter), each capped onone end and manifolded to a bank of compressors on the other end. A gasaccumulator may deliver gas pressure to one side of a fluid pistonconnected to an orifice. Fluid pressure (e.g., drilling fluid pressure)may be delivered to another side of the fluid piston. The pressureacross an orifice (e.g., a surface orifice providing access to afracking string) may remain constant and volume of fluid flowing throughthe orifice may be varied by varying the gas pressure delivered usingthe gas accumulator and/or a flow throttle.

Apparatus and Systems

The present disclosure relates, in some embodiments, to kinetic frackingapparatus and systems in which the kinetic energy of a fluid in motionis applied to a geological structure to promote formation of fracturesin the structure. A kinetic fracking system may comprise, for example, afracking string having a central channel and a central channel axis, agenerally concentric fluid velocity activated annular valve axiallyslidable and comprising a ramp, a generally concentric packing elementin communication with the ramp and configured for radially outwardtranslation upon axial movement of the ramp, and/or a generallyconcentric spring in communication with the valve and configured to becompressed by axial movement of the valve. A valve ramp may extend overthe full circumference and at least a portion of the length of a valve.Its maximum extent (e.g., largest diameter) may be positioned at themore downhole end of the valve and/or its minimum extent (e.g., smallestdiameter) may be positioned at the end of the valve nearer to the wellhead. The narrower end of a valve taper or ramp may include a fixationzone (e.g., a threaded zone) where a retainer plate may be secured. Aretainer plate may restrict and/or prevent axial movement of a packingelement such that the packing element is biased to move radiallyoutwardly. A retainer plate may contact a spring and/or restrict orprevent (e.g., alone or together with a housing) movement of a springother than compression and expansion. A valve may be sealably attachedto and/or contiguous with a generally concentric annular piston (e.g.,comprising rubber and/or fabric). A piston may extend radially outwardlyfrom a valve and occlude (e.g., substantially occlude) the cavitybetween a liner and a fracking string. A housing may be secured to afracking string, for example, by mated threaded zones positioned at thewell head end.

During initial stages of fracking, flow velocity may be high (e.g.,extremely high) and may suffice to keep high density material insuspension. As fractures progress into a formation and propping agentsare wedged into the fractures, fracture fluid pressure may be reduced orlost due to friction and/or obstruction(s) in the formation. Thisreduction or loss of pressure may result in a lower flow rate and, ifcontinued, injection flow may stop. Lower flow rates may not besufficient to keep high density material in suspension. For example, insome operations, a difference in the specific gravity of the frackingsand and fluid at low flow rates may allow gravity settling of thehigher specific gravity material, which in turn, may block flow.Fracking sand and/or ceramic propping agents (e.g., having a specificgravity of 2.5 may settle out of a fracking fluid (e.g., having aspecific gravity of 1.2), which may obstruct a well string bore and/orreduce the available flow work or kinetic energy available forfracturing a subterranean structure. Such obstructions, if formed, mayhinder efforts to reinitiate flow and/or achieve desired flow rates.

Systems, methods, and apparatuses may, in some embodiments, beconfigured and/or operated to avoid sedimentation of fracking sand froma drilling fluid. A kinetic fracking system may comprise, for example, afracking string having a central channel and a central channel axis, thecentral channel having a (proximal) surface end and a (distal) formationend, a generally concentric annular velocity valve including a ramp, agenerally concentric annular fluid velocity-activated annular valveassembly that is axially slidable (a slider valve assembly) positionedproximal to the velocity valve, a generally concentric packing elementin communication with the ramp, a generally concentric first spring incommunication with the proximal end of the slider valve assembly, and/ora generally concentric second spring in communication with the distalend of the slider valve, wherein the first and second spring may beconfigured to be compressed by opposite axial movements of the slidervalve. A slider valve may comprise and a frack string may each comprisean orifice, according to some embodiments. A slider valve hole and afrack string hole may be configured and arranged, in some embodiments,to permit, when aligned, fluid communication between the inside diameter(ID) of a frack string and the annular space between the frack stringouter diameter (OD) and the production casing ID.

In some embodiments, a down hole slider valve may configured to allowtheir respective orifice(s) to substantially align or align when theformation stops taking frack fluid and the flow velocity approacheszero, thereby permitting fluid to move from the frack string ID to theannular space. For example, flow from the frack string to the annularspace Systems, apparatus, and methods may include configuring a springforce to be responsive to differential pressure across an orifice (e.g.,connecting a frack string ID and the annulus between the frack string ODand the production casing ID) such that it causes a slider valve toshuttle from an open position to a closed position as a function offrack fluid flow rate. For example, at high flow rates, the slider mayhave an open position. As flow rate drops, a slider may move to a closedposition. At (or near) zero flow the spring force may cause the valve tomove to an open position and allow flow from the frack string innerdiameter to the annulus to resume. Resuming flow may includeaccelerating a frack fluid mass inside of the frack string to a velocity(e.g., a desired velocity, a maximum velocity). In some embodiments,resuming flow may again initiate a kinetic energy event. Each successivekinetic event may allow any sand or ceramic bead accumulation in thefrack string to be flushed to the annulus, thereby reducing and/orclearing any blockage that might otherwise hinder flow and formationfracturing. At high (e.g., maximum) flow, differential pressure across aflow orifice to the annulus may cause the valve to return to the closedposition as a compression spring is compressed from the differentialpressure force and a valve mandrel slides to the closed position.

Specific Example Embodiments

Specific example embodiments of a fracking system are illustrated inFIG. 1. As shown, gas in high pressure accumulator 104 and/or the gasside of accumulator 114 may be pressurized by high pressure gascompressor 106 connected via high pressure gas supply line 108. Gas maybe admitted to high pressure accumulator 104 by high pressure gas inputvalve 110. High pressure gas accumulator 104 is in communication withwell head 142 and may deliver gas under the control of programed gasthrottling valve 102.

Fluid may be mixed with gas in high pressure accumulator 114. Gas isadmitted from high pressure gas compressor 106 by high pressure gasinlet valve 112 and contacted with fluid in fluid side 118 by the actionof piston 116. Program controlled fluid bypass valve 128 may admitmetered portions of gas/fluid mixture from accumulator 114 to pumpbypass line back to suction 126 where it is conveyed to high pressurefrack pump 122. The mixture may then be returned to accumulator 114 withany needed additions of make-up fluid added by fluid accumulator make upline 124. Gas side high pressure gas accumulator 114 is in communicationwith well head 142 and may deliver gas/fluid there under the control ofprogrammed throttling valve 120. As FIG. 1 illustrates, dopant may beadded to the gas/fluid mixture exiting accumulator 114 to form frackfluid containing proppants 134 as shown using one or more dry dopantdispensers 130 regulated by program controlled metering valve 132. Thus,fluid 134 and gas 136 combine to deliver fluid at high velocity to wellhead 142 and production string 144 positioned inside of production liner138. Movement of the combined fluid may be abruptly stopped downhole bythe action of a fluid velocity activated annular valve 146 or a pressureactivated packer 148. This may result in the delivery of a high energypulse at production zone 198.

Valve 140 may be installed on all wells. As show, valve 140 may beattached to the wellhead and may give access to the annulus between theinside diameter of the production string and the internal tubing stringor drill pipe while the well is being drilled. Valve 140 may be used asa choke line valve in the prevention of a well blowout by holding a backpressure on a formation. Any gas that has not been injected into theformation and is displaced up the annulus may start to expand with eachincrement up the hole and, thereby, reduce the hydrostatic head on theformation. In some embodiments, a computer program may be configured(e.g., programmed) to maintain a constant discharge pressure at the wellhead by throttling the valve.

Specific example embodiments of a fluid velocity activated annular valvesystem are illustrated in FIGS. 2A, 2B, and 2C. As shown, productionliner 289 having spaced apertures 291 is positioned in well bore 297. Inoperation, high velocity frack fluid flows (open arrow) down the insidediameter of frack string 251. It enters the annular space between string251 and liner 289 through apertures 255 and 265. In some embodiments,frack string 251 may include a dead end to the right of the portionshown in FIG. 2A. Fluid passes through restricted flow area 287 betweenhousing 269 and liner 289. The high velocity frack fluid sees a pressuredrop through the restriction so that P1 is greater than P2. Annularsliding valve body 259 may encircle interior channel wall 253 of string251. A seal may be formed between string 251 and velocity valve 259 byO-rings 267 positioned between the two and at either end of valve 259.Annular valve 259 may be fixed to annular (flared) rubber and fabricpiston 285. Piston 285 may include a surface facing (proximal to)aperture 265 and a surface facing away from (distal to) aperture 265.

When the pressure acting on the proximal surface (e.g., P1) exceeds thesum of the pressure acting on the distal surface (e.g., P2) plus thespring constant of spring 283, valve 259 moves to the left (closedarrows). As valve 259 moves to the left, spring 283(housed in chamber284) is compressed. Translation of valve 259 abruptly stops flow offracking fluid because ramp 277 of packing element 275 slides acrossramp 261 of valve 259 moving packing element 275 radially outwardly toform a seal with string 289. At this time frack fluid flow back to thesurface is terminated and the entire mass of frack fluid inside the workstring is abruptly decelerated creating a large kinetic energycomponent. A period of static flow conditions occur. Surface gas andfluid accumulators may now supply maximum design pressure to theproduction formation that has been exposed through casing ports 291.

Annular piston chamber 274 is in fluid communication with spring chamber284. Piston chamber 274 may be sized to correspond in volume to springchamber 284 or sized to correspond to the volume of the spring chamberdisplaced by ring 279/valve 259 during a stroke. Piston 273 may beallowed to free float within chamber 274. When piston 273 is displacedto the right, frack fluid may occupy chamber 274. As retainer ring 279compresses spring 283 the, fluid (e.g., high viscosity/ high temperaturegrease) flows out of spring chamber 284 and enters chamber 274 drivingpiston 273 leftward and displacing frack fluid (if any). Frack fluid maybe permitted to enter and exit the void shown in FIG. 2B defined byvelocity valve 259, collar 269, packing element 275, and retaining ring279 during each stroke. In some embodiments, measures may be taken toreduce or prevent infiltration of frack fluid into chamber 284. Forexample, ring 279 may be fitted with one or more seals (e.g., O-rings onits outer diameter).

Flow conditions change from static to dynamitic at formation breakdown(e.g., formation of fractures 299). Assuming sufficient accumulatorvolume capacity combined with pump and compressor make up feed, aconstant pressure variable demand volume flow condition will occur sothat fracture propagation and proppant placement will proceed on acontinuous basis until such time as the pressure drop through thefracture zone exceeds that necessary to cause further formation failure.At this time flow into the hole will stop at full pressure. If there isno pressure bleed down closing off the accumulator valves and ventingthe frack fluid, P1 and P2 will equilibrate and work string will resetthe fluid velocity valve to open (shifted to the right as shown in FIG.2A) as the only force acting will be compression spring 283. Piston 273and fluid in chamber 274 will correspondingly move rightward. Asdesired, this action may allow another pulse sequence to be initiated.

Valve 259, as shown, includes a uniform inner diameter mated to theouter diameter of wall 253. Valve 259 also includes threaded zone 263,which is matched to threads 281 of retainer plate 279. Retainer plate279 cooperates with ramp 261 to generate radially outward travel ofpacking element 275. Threads 271 of housing are secured to threads 259of fracking string 251. Valve 259 may comprise steel compression moldedwith a combination of extremely high strength fabric such as Dacron anda high strength polymer such as polyurethane. The first coil of spring283, pressing against retainer plate 279 is machined to act as a back upto the polymer as a differential pressure of 8000 to 10000 psi may occurbetween the retainer plate and the packing element.

As shown in FIG. 2C, velocity valve 259 comprises generally tubular body260 having proximal taper 261, neck 262, threads 263, flange 264,apertures 265, and distal neck 266. Proximal neck 262 and distal neck266 may have the same or substantially the same outer diameter. Thelength of taper 261, neck 262, threads 263, flange 264, apertures 265,and 266 may be independently varied as desired or required. Theposition, size, shape, and/or number apertures 265 independently may bevaried. In some embodiments, the position, size and number are selectedaccording to the position, size, and number of apertures 255. Forexample, apertures may be aligned at the beginning of a cycle and closed(not aligned) in the middle of a cycle. Apertures may be configured topermit flow throughout a cycle, even if fluid isn't actually flowing.The position of threads 263 on taper 261 and the angle of taper 261independently may be varied as desired or required, the length and taperposition of apertures 265 along neck 266 may be varied as desired orrequired. The inner surface of body 260 may be uniform, substantiallyuniform, or contoured (e.g., to accommodate a seal). Although notexpressly shown, valve 259, housing 269, retainer 279 and/or any othermembers that slide or house a sliding member and/or any subparts thereofmay have one or more inner diameter and/or outer diameter surfacefeatures to restrict and/or prevent rotation.

Valve 259, if installed in the correct position in a casing annulusmight mitigate or prevent blowouts by sealing off high pressure downholeto surface flow. Although string 251 and valve 259 are depicted in ahorizontal orientation in FIGS. 2A and 2B, they may be positioned at anydesirable angle desired or required by downhole conditions.

Specific example embodiments of a fluid velocity activated annular valvesystem are illustrated in FIG. 3A, FIG. 3B, and FIG. 3C. As shown inFIG. 3A, production liner 389 having spaced apertures 391 is positionedin well bore 397. In operation, high velocity frack fluid flows down theinside diameter of frack string 351. In some embodiments, frack string351 may include a dead end to the right of the portion shown in FIG. 3A.There is a pressure drop across orifice 371 (P3) as long as fluid flowsthrough the inside diameter of frack string 351. A flow port 385associated with frack string 351 is also shown in FIG. 3A. Over of time,fluid flow through the inside diameter of frack string 351 may bereduced, for example, as the subterranean structure fills with fluidand/or resists further breakdown. As this fluid flow is reduced, thepressure drop across orifice 371 is also reduced. This pressure dropserves as a balancing pressure against spring 372. When the pressuredrop falls below a desired, defined, and/or preset threshold, spring 372overrides the reduced pressure drop across orifice 371, thereby allowingthe sliding valve 373 to move horizontally and align (and open) ports355, 365 to the annulus 374. The sliding valve 373, along with any ofthe other elements illustrated in FIGS. 3A, 3B, and 3C may be coupled toand associated with one or more seals 358. Opening the ports 355, 365causes fluid to flow through from the frack string 351 to the annulus374. Fluid is then free to flow to the annulus 374 (which may extend toor be in fluid communication with the surface), allowing the full columnof the frack fluid to accelerate (back) to its maximal or desired rateand initiation of a kinetic energy event (e.g., an additional kineticenergy event). Therefore, in some embodiments, as the flow ratedecreases, the differential pressure between P1 and P3 decreases,thereby causing the sliding valve 373 to move toward the left.

Opening the ports 355, 365 causes at least a portion of the annulus 374to act as an orifice. The orifice associated with the annulus 374 isdesigned to produce a pressure drop at maximum fluid flow so that thecombined differential pressure drop force across the orifice associatedwith the annulus 374 and orifice 371 combined with spring 375′scompression causes the sliding valve 373 to close off flow to annulus374. Spring 375 and spring 372 are offset by forces created by pressuredrops across the orifice associated with the annulus 374 and orifice371, respectively. In some embodiments, spring 375 is offset by forcecreated by a pressure drop across orifice 376 (P2), rather than, or incombination with, a pressure drop across the orifice associated with theannulus 374. While snap rings 386, 387 are illustrated in FIG. 3A, thefunctionality of the snap rings 386, 387 is explained in further detailin FIG. 4. In some embodiments, any of the orifices described herein maybe controlled using a computer-controlled device. The structure andfunctionality of FIG. 3A is primarily described with respect to theupper part of the fluid velocity activated annular valve system. Thelower part of the fluid velocity activated annular valve system may havesimilar structure and functionality as well.

FIG. 3B is a close-up version of a portion of FIG. 3A. FIG. 3B shows alocking taper 377 comprising metal expandable coil springs 378, 379 toback up piston rubber and prevent extrusion at high pressure levels. Insome example embodiments, the locking taper is less than 1.5 inches perfeet. The coil springs 378, 379 are coupled to polymer elements 381, 382(e.g., carbon fiber elements). The locking taper prevents the flow offluid through an area locked by the locking taper. The annular velocityvalve 383 is locked in place and does not move. FIG. 3C shows the systemof FIG. 3A such that fluid passes through ports 355, 365, which may ormay not be aligned either partially or totally, to the annulus 374.Spring 375 is compressed in FIG. 3C, while it is not compressed in FIG.3A. Spring 372 is not compressed in FIG. 3C, while it is compressed inFIG. 3A. Therefore, FIG. 3C illustrates an annulus flow open position,while FIG. 3A illustrates an annulus flow closed position. Any orifice,aperture, or opening described in this specification may have anydesired shape and size.

Specific example embodiments of a fluid velocity activated annular valvesystem are further illustrated in FIG. 4. In some embodiments, at fullflow rate, a slider sleeve 413 may be force balanced in an annulus flowclosed position such that flow is directed into a formation, but notinto an annular space 419 between a fracking string and a liner. As theformation starts to resist flow, the flow rate into the formation fallsand the pressure drop across orifice 411 decreases. When the pressuredrop falls to and/or below a threshold level, spring 412 moves slidersleeve 413 to an annulus flow open position such that fluid is permittedto enter the annular space 419 between frack string and liner. Seals421, 422 are coupled to and associated with the slider sleeve 413. Ifthis flow is relatively impeded as may be desired, fluid flow rate onceagain increases. Sliding valve 413 may be configured to return to anannular space 419 closed position once the flow rate rises above adesired level. The formation is thus exposed to the kinetic energy ofthe flowing (e.g., rapidly flowing) fluid.

A decrease in pressure across orifice 411 allows spring 412 to overridethe pressure dropped across orifice 412 resulting in slider sleeve 413taper exerting force on a matching taper of snap ring 415. As fluid flownears zero, spring 412 is designed to force open snap ring 415 andcompress spring 416. Slider sleeve 413 moves to the annulus openposition and snap ring 415 taper engages matching slider sleeve 413taper. Full fluid flow is now to the annulus allowing maximumacceleration of the full column of the frack fluid and reinitiation of akinetic energy event. Orifice 417 is designed to produce a pressure dropat maximum fluid flow so that the combined differential pressure dropforce across orifice 411 and orifice 417 combined with spring 416'scompression force forces snap ring 418 outward and allows slider sleeve413 to close off the annulus. In some embodiments, spring 416 is offsetby force created by the pressure drop across orifice 423, rather than,or in combination with, the pressure drop across the orifice 417 goingto the annular space 419.

Calculated flow rates, pressures, and forces for a specific exampleembodiment are shown below. Such calculations may be used, according tosome embodiments, to plan, predict, and/or determine various aspects ofsystems illustrated and described herein. For example, the calculationsshow the net theoretical force from a pressure drop across an orifice(e.g., orifice 417) and the quantity of fluid required to compress aspring (e.g., spring 351). The amount of kinetic energy generated usingany of the systems described herein may produce a pressure of 30000 psiin approximately 5 seconds. In the calculation below, Ft or ft standsfor feet, ID stands for diameter, in stands for inches, gal stands forgallons, min stands for minutes, Wt stands for weight, psi stands forpounds per square inch, KE stands for kinetic energy, FW stands for flowwork, P stands for pressure, sec stands for seconds, vel stands forvelocity, in stands for inches, CO₂ stands for carbon dioxide, and HPstands for horsepower.

Vertical depth = 16000 Ft Frack String ID = 4 in Frack String area =0.087222 Ft² Orifice ID = 3 in Orifice area = 0.049063 Ft² Total flowrate = 4000 gal/min CO₂ % by vol = 0.3%*100 Frac fluid % by Vol = 56.00Sand % by Vol = 14.00 sg sand = 2.5 sg water = 1 frack fluid #/gal = 10#/gal sand #/gal = 20.86 #/gal WtCo2 @8000 psi = 0.12 #/sec Weight offluid 373.33 #/sec Weight of sand 194.65 #/sec Total Wt = 568.11 #/SecVel in 4″ ID = 102.18 ft/sec Vel in Orifice = 181.66 ft/sec KE1 = 92110ft #/sec KE2 = 291113 ft #/sec assume P1 = 8000 psi 8000 Flow = 8.91ft³/sec FW1 = 10267380 ft #/sec (KE1 + FW1) = KE2 + FW2 FW2 = vel2*area2*P2 (KE1 + FW1 − KE2)/ (vel2*area2) = P2 P2 = 7845 P1 − P2 155#/in{circumflex over ( )}2 or 22328.12 Net force from differential 852pounds pressure to compress spring = Ratios: Frac fluid and sand = 70%by volume Co2 = 30% by volume Frac fluid = .70 times .80 Times totalvolume Sand = .70 Times .20 times total volume Kinetic Energy = 11847341ft pounds/second or 21541 HP/Sec

As will be understood by those skilled in the art who have the benefitof the instant disclosure, other equivalent or alternative kineticfracking compositions, devices, methods, and systems can be envisionedwithout departing from the description contained herein. Accordingly,the manner of carrying out the disclosure as shown and described is tobe construed as illustrative only.

Persons skilled in the art may make various changes in the shape, size,number, and/or arrangement of parts without departing from the scope ofthe instant disclosure. For example, the position and number of pumps,accumulators, valves, apertures, and controllers among others, may bevaried. The size of an apparatus and/or system may be scaled to suit theneeds and/or desires of a practitioner. Each disclosed method and methodstep may be performed in association with any other disclosed method ormethod step and in any order according to some embodiments. Where theverb “may” appears, it is intended to convey an optional and/orpermissive condition, but its use is not intended to suggest any lack ofoperability unless otherwise indicated. Persons skilled in the art maymake various changes in methods of preparing and using a composition,device, and/or system of the disclosure. Elements, compositions,devices, systems, methods, and method steps not recited may be includedor excluded as desired or required.

Also, where ranges are provided, the disclosed endpoints may be treatedas exact and/or approximations as desired or demanded by the particularembodiment. Where the endpoints are approximate, the degree offlexibility may vary in proportion to the order of magnitude of therange. For example, on one hand, a range endpoint of about 50 in thecontext of a range of about 5 to about 50 may include 50.5, but not 52.5or 55 and, on the other hand, a range endpoint of about 50 in thecontext of a range of about 0.5 to about 50 may include 55, but not 60or 75. In addition, it may be desirable, in some embodiments, to mix andmatch range endpoints. Also, in some embodiments, each figure disclosed(e.g., in one or more of the examples, tables, and/or drawings) may formthe basis of a range (e.g., depicted value +/− about 10%, depicted value+/− about 50%, depicted value +/− about 100%) and/or a range endpoint.With respect to the former, a value of 50 depicted in an example, table,and/or drawing may form the basis of a range of, for example, about 45to about 55, about 25 to about 100, and/or about 0 to about 100.Disclosed percentages are weight percentages except where indicatedotherwise.

All or a portion of a kinetic fracking device and/or system may beconfigured and arranged to be disposable, serviceable, interchangeable,and/or replaceable. These equivalents and alternatives along withobvious changes and modifications are intended to be included within thescope of the present disclosure. Accordingly, the foregoing disclosureis intended to be illustrative, but not limiting, of the scope of thedisclosure as illustrated by the appended claims.

The title, abstract, background, and headings are provided in compliancewith regulations and/or for the convenience of the reader. They includeno admissions as to the scope and content of prior art and nolimitations applicable to all disclosed embodiments.

1.-10. (canceled)
 11. A system for kinetically fracking a subterraneanstructure, the system comprising: (a) a well in fluid communication withthe subterranean structure; (b) a well liner inside the well; (c) afracking string inside the well liner, the fracking string comprising acentral channel; and (d) a fluid velocity activated annular valveconfigured to abruptly decelerate the fracking fluid.
 12. A system forkinetically fracking a subterranean structure according to claim 11further comprising from one to about twenty additional high pressure gaspumps, each independently configured to deliver 1500 to 2000 horsepower.13. A downhole fluid velocity activated annular valve configured foroperation in a wellbore with an inserted production liner, the valvecomprising: (a) an annular body having a longitudinal axis, an interiorsurface configured to slide along and seal a fracking string, and anexterior surface comprising a taper, the taper extendingcircumferentially around the exterior surface and extending along atleast a portion of the length of the body; (b) an annular packingelement contacting and surrounding the taper and configured to translateradially outwardly upon axial movement of the ramp; and (c) at least oneaperture configured to align with a corresponding hole in the frackingstring and support fluid communication between the inner channel of thefracking string and the liner cavity.
 14. A downhole fluid velocityactivated annular valve according to claim 13, further comprising anannular housing surrounding an annular spring, the spring configured forcompression and decompression with axial movement of the valve; orwherein the maximum extent of the taper is positioned at the moredownhole end of the valve and/or the minimum extent of the taper ispositioned at the end of the valve nearer to the well head. 15.(canceled)
 16. A downhole fluid velocity activated annular valveaccording to claim 13 further comprising an O-ring on the inner surfaceconfigured to sealably contact the fracking string. 17-19. (canceled)